Measuring and modifying directionality of seismic interferometry data

ABSTRACT

Methods and apparatuses are disclosed for replacing the individual receivers used with a seismic interferometry process with an array of seismic receivers and then manipulating the array data in order to measure and modify the typical non-uniform directionality function of the background seismic energy. The non-uniform directionality function is a significant cause of noise with seismic interferometry. Furthermore, the array of receivers may be used to significantly enhance the preferred reflection energy and damp undesirable near surface energy. The directionality function may be modified by using an array of receivers for the virtual source location of seismic interferometry to measure the non-uniform directionality function, generating multiplication factors, and applying the multiplication factors to convert the measured directionality function into a desired directionality function.

RELATED APPLICATION INFORMATION

This application claims priority from U.S. Provisional Application Ser.No. 61/093,996 entitled “MEASURING AND MODIFYING DIRECTIONALITY OFSEISMIC INTERFEROMETRY DATA” filed on Sep. 3, 2008, the entiredisclosure of which is incorporated by reference herein.

FIELD OF THE INVENTION

The present invention relates to seismic surveying and more particularlyto seismic interferometry.

BACKGROUND

Seismic surveying techniques use reflected seismic waves to determineunderground geologic structure. One manner of seismic surveying uses anactive source to generate one or more controlled seismic waves. Theactive source may, for example, be an explosive, an air gun or avibrator truck. The seismic waves generated by the active source arereflected off of underground geologic structure, and the reflectedseismic waves are typically recorded by a plurality of receivers such asseismic motion sensors, geophones, accelerometers, or hydrophones. Therecordings may be vertical ground motion (velocity or acceleration),pressure, components (e.g. three directions) of ground motion or acombination thereof. Seismic data processing methods are then used toprocess the recorded response and produce an image of undergroundgeologic structure therefrom.

Seismic interferometry is a method of seismic data collection andmanipulation or processing that is able to use a receiver as a virtualsource to simulate and replace an active source. Typically, seismicwaves are recorded at a primary location (the virtual source location).The seismic waves recorded at the primary location may be deliberate ornon-deliberate seismic waves present in the earth such as, for example,natural background seismic waves due to ocean wave action, seismic wavesdue to vehicle traffic, or even seismic waves caused by a remotelypositioned active source. At the same time, seismic waves are alsorecorded at at least one additional location, a secondary location ofthe seismic interferometry process. The time series recorded at thesecondary location is deconvolved using the time series recorded at thevirtual source location. In instances where the receivers measuremultiple components of ground motion, the deconvolution is performedbetween each of the components. Since the seismic waves recorded at thevirtual source location are reflected from the surface of the earth, aportion of these reflected seismic waves will reflect off of undergroundgeologic structure and reach the additional location. In this regard,the deconvolution of the components of the time series recorded at thesecondary location contains the same response as there would be if therewas a source for each of the ground motion components at the primarylocation generating seismic waves being recorded by a receiver at theadditional location. Thus, this seismic interferometry data maysubstitute for conventional active seismic source data. Active sourceseismic data processing methods may then be used to produce an image ofunderground geologic structure in a manner similar to active sourceseismic surveying.

SUMMARY

The present invention facilitates the use of seismic interferometrictechniques in determining underground geologic structure. In thisregard, one difficulty with the seismic interferometric approach is thatthe seismic wavefield recorded at the virtual source often has anundesirable directionality pattern or function. A directionalitycomponent of the recorded seismic wavefield used for seismicinterferometry (e.g., energy coming from one angle and azimuth) can andoften does have significantly different strength or amplitude than otherdirectionality components of the seismic wavefield (e.g., energy comingfrom other angles and/or azimuths). As a result, the virtual source fromseismic interferometry will have a non-uniform energy directionalitypattern or function. This non-uniform energy function may exist for eachground motion component. This situation is different from an activesource for which the energy directionality function is generally wellknown and often uniform in angle and azimuth.

The current state of the art of seismic interferometry does not considerthe non-uniform directionality of the energy at the virtual source anddoes not provide for a method to measure it and correct for it. In thisregard, many proposed seismic interferometric techniques only considersingle receivers at the virtual source location. With a single receiver,it is not possible to measure the directionality of the seismic energy.

Embodiments described herein present, inter alia, methods to measure andcorrect the non-uniform directionality function of the vibrationsrecorded at the virtual source location when performing seismicinterferometry by replacing the single receiver that acts as a virtualsource with an array of receivers, which will usually be two dimensional(2D), but may be one dimensional (1D). The use of an array of receiversat the virtual source location allows for measuring the strength of thenon-uniform directionality function of the seismic energy recorded atthe virtual source location by applying beam forming or related methodson the array to transform the data into different directionalitycomponents.

After the strength of the directionality components is measured,multiplication factors can be determined to change the directionalitycomponent strengths to produce a desired directionality function. Themultiplication factors may, for example, be determined by dividing thedesired strength of a directionality component with the measuredstrength. This may be performed subject to damping criteria andtapering. The multiplication factors may then be applied by adjustingthe strength of the directionality components in one of several ways ineither the seismic interferometry operation or in the conventionalseismic data processing. The measurement of the directionalitycomponents, the determination of the multiplication factors, and theapplication of the multiplication factors can be performed for eachground motion component.

Embodiments described herein enable the non-uniform directionality ofseismic energy received at a virtual source during a seismicinterferometry process to be measured and corrected for in laterprocessing. This may result in a more accurate geologic survey thancould be accomplished using known seismic interferometry processes. Inthis regard, the embodiments described herein may enable expanded use ofinterferometric virtual source methods, which has several advantagesover traditional active source seismic surveying. For example, sincereceivers are less expensive than active seismic sources, there may be acost savings involved with replacing an active source with an array ofreceivers. Furthermore, the potential for environmental damage and therisks associated with explosives and heavy machinery inherent in the useof an active source can be avoided, or at least mitigated by positioningthe active source in a less sensitive area. Also, receivers may beeasier to place in difficult locations, such as hilly terrain or inpopulated areas.

According to an aspect, a method of performing seismic interferometry toobtain information related to subsurface structure includes positioninga plurality of seismic receivers to receive seismic waves, using atleast one of the seismic receivers as a secondary location receiver forseismic interferometry, recording a time series of seismic wavesincident on each seismic receiver, and modifying a directionalityfunction of the virtual source for seismic interferometry.

The positioning may include arranging at least a portion of theplurality of seismic receivers in an array within an area associatedwith a location of a virtual source for seismic interferometry. Theseismic receivers may be distributed in a uniform or non-uniform mannerover the area. The positioning and quantity of seismic receivers may beat least partially dependent on the surface wavelength corresponding tothe lowest and highest frequency seismic waves to be recorded. Seismicreceivers used as a secondary location receiver for seismicinterferometry may be among the portion of the plurality of seismicreceivers arranged in the array or they may be separate from the portionof the plurality of seismic receivers arranged in the array.

Modifying the directionality function may involve combining at least twoof the time series from the seismic receivers included in the array. Thecombining may include performing a spatial domain transform over thearray locations of the time series of seismic waves incident on eachseismic receiver of the array. This transform may separate the seismicwaves incident on the array into different directionality components.Each directionality component may correspond to a value of thedirectionality function.

Multiplication factors, time shifts, and phase shifts may be applied tothe data traces from at least two of the individual receivers of thearray. The multiplication factors may be applied in the transform domainor equivalent ones may be applied in the spatial domain of the originaldata. Additionally, the multiplication factors may be applied byelectronically joining the receivers in the field. Further, themultiplication factors may be applied when performing a seismicmigration, an imaging, an inversion process or a combination thereof.Regardless of how they are applied, the multiplication factors may beused to obtain a uniform directionality function or an intentionallynon-uniform directionality function.

According to an aspect, a method of modifying a directionality functionof a virtual source used in seismic interferometry includes recordingseismic wave data incident on each individual seismic receiver of anarray of seismic receivers, performing a domain transform on therecorded seismic wave data to separate the recorded seismic wave datainto different transform components, measuring a signal strengthmeasurement for each transform component, and determining multiplicationfactors to convert the measured signal strength for each transformcomponent into a desired strength for each transform component. Thevirtual source for the seismic interferometry may be associated with thearray of seismic receivers where each receiver of the array has anassociated location within the array. The determination of themultiplication factors may include dividing the desired strength foreach individual transform component by the measured signal strength foreach individual transform component.

According to an aspect, a seismic interferometric system operable toobtain information related to subsurface structure includes a pluralityof seismic receivers, at least one recording device operable to record atime series of seismic waves incident on each of the plurality ofseismic receivers, and a processor operable to modify a directionalityfunction of the virtual source for seismic interferometry. The pluralityof seismic receivers may be positionable such that a portion of them maybe arranged in an array within an area associated with a location of avirtual source for seismic interferometry. At least one of the pluralityof seismic receivers may be used as a secondary location receiver forseismic interferometry. Modifying the directionality function mayinvolve combining at least two of the time series from the seismicreceivers included in the array.

The processor may be further operable to perform a spatial domaintransform over the array locations of the time series of seismic wavesincident on each seismic receiver of the array. In this regard, theprocessor may be operable to separate the recorded seismic wave datainto different transform components. Each of these transform componentsmay correspond to a type of wave that has some directionality. Theprocessor may further be capable of measuring a signal strengthmeasurement for each transform component and determining multiplicationfactors to convert the measured signal strength for each transformcomponent into a desired strength for each transform component.

According to an aspect, a computer program product includes a computerusable medium having computer program code embedded therein. Thecomputer program code may include computer readable program code thatmay enable a processor to read a data file including a time series ofseismic waves incident on each seismic receiver of an array of seismicreceivers, read a data file including a time series of seismic wavesincident on a secondary location receiver for seismic interferometry,and modify a directionality function of a virtual source for seismicinterferometry. The array may be associated with a location of a virtualsource for seismic interferometry. The modifying of the directionalityfunction may involve combining at least two of the time series from theseismic receivers included in the array. Moreover, the computer readableprogram code may enable the processor to perform a spatial domaintransform over the array locations of the time series of seismic wavesincident on each seismic receiver of the array. This transform mayseparate the time series of seismic waves incident on each seismicreceiver of the array into different directionality components, whereeach directionality component may correspond to a value of thedirectionality function.

Additional aspects and corresponding advantages of the present inventionwill be apparent to those skilled in the art upon consideration of thefurther description that follows.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A is a cross sectional schematic view of a seismic sensor placedon the Earth's surface and a set of sample seismic directionalitycomponents with different amplitudes incident upon the seismic sensor.

FIG. 1B is a cross sectional schematic view of the sensor of FIG. 1A andreflected directionality components with different strengths.

FIG. 2 is a partial cross sectional schematic view of a set of sensorsplaced on the Earth's surface.

FIGS. 3A, 3B and 3C are top schematic views of exemplary sensor arrays.

FIGS. 4A and 4B are cross sectional schematic views of the sensor ofFIG. 1A and reflected directionality component vectors aftermodification.

FIG. 5 is a flowchart for one embodiment of a method of performingseismic interferometry.

FIG. 6 is a flowchart for one embodiment of a method of modifying adirectionality function of a virtual source used in seismicinterferometry.

FIG. 7 is a block diagram of one embodiment of a system operable toobtain and store seismic data, modify a directionality function of avirtual source and perform seismic interferometry.

DETAILED DESCRIPTION

As noted above, seismic interferometry utilizes seismic energy incidentupon a particular location as a virtual source of seismic waves for aseismic survey. FIG. 1A is a cross sectional schematic view showing areceiver 101 placed on the Earth's surface 102 at a particular location104. A plurality of seismic directionality components (referred toherein alternatively as directionality components) incident at thereceiver 101 are represented by directionality component vectors 103 athrough 103 g. A seismic directionality component is the portion of theseismic waves incident on the receiver from a specific direction. Asillustrated, the seismic directionality components incident at location104 may be non-uniform, and the varying size of the illustrateddirectionality component vectors 103 a through 103 g represents thevarying amplitudes of directionality components incident at the location104. These directionality components are separate for each ground motioncomponent recorded at the receiver.

When performing seismic interferometry using data that has not beenmodified or filtered to take into account the non-uniformity of thedirectionality components incident at the virtual source location, thenon-uniformity of the directionality components may distort the geologicimage resulting from the seismic data processing and may amplify thenoise in the data. This noise may result in a degraded image of thegeologic structure after processing relative to an image that can beobtained from the data if the non-uniformity of the directionalitycomponents is reduced or eliminated.

However, a single receiver, such as receiver 101 illustrated in FIG. 1A,is not capable of measuring the non-uniformity of the directionalitycomponents incident at location 104. If the non-uniformity of thedirectionality components is not known, the data collected cannot becorrected for the non-uniformity.

Embodiments of the present invention facilitate eliminating or reducingeffects from the non-uniformity of directionality components incident atthe location of a virtual source used in seismic interferometry. Thismay be achieved by using an array of receivers to record seismic wavesincident at the virtual source location of seismic interferometry whileat the same time recording, with an individual receiver, seismic wavesincident at the secondary location of seismic interferometry.Additionally, and at the same time, other individual receivers may berecording seismic waves incident at additional secondary locations.Moreover, individual receivers located in the array may be used as partof the virtual source array and as a secondary location for seismicinterferometry. The receivers may be operable to record multiple groundmotion components and each ground motion component may be treatedseparately.

The data collected at the array may be spatially transformed into adifferent domain where each transform component of the new domaincorresponds to an approximate directionality of the seismic energy. Thenon-uniformity of the directionality components may then be measured.Multiplication factors may then be determined that modify thenon-uniform recorded directionality components into, for example,uniform components or components with a deliberate desired non-uniformdistribution that improve the final processed image. The multiplicationfactors may be applied in a number of manners and at different stages ofseismic data processing including as described herein. This process ofmeasuring the strength of directionality components, determiningmultiplication factors, and modifying the directionality function can beperformed separately for each ground motion component.

The application of the multiplication factors may result in a seismicinterferometry signal without the effect of the non-uniform strength ofthe directionality components. The resulting virtual source may simulatean active source with a uniform energy distribution over alldirectionality components or a source with a deliberate non-uniformenergy distribution that boosts desired directionality components anddamps undesirable directionality components.

As noted above, an array of receivers may be used to collect seismicdata from which directionality components may be determined. Anexemplary arrangement is illustrated in FIG. 2. In FIG. 2, an array 201of receivers is positioned on the Earth's surface 203 in an area 202,which is the virtual source location of seismic interferometry. Eachindividual receiver of the array 201, such as receiver 204 a may becapable of obtaining a time series recording of seismic activity at itslocation.

Generally, the array 201 may be one dimensional (e.g. a single row ofreceivers) or two-dimensional (e.g., multiple rows and columns ofreceivers) and the individual receivers of the array 201 and individualreceivers outside of the array, such as individual receivers 205 and206, may be located at or near the surface 203. As used herein, theterms “one-dimensional” and “two-dimensional” may include arrays whereone or more of the individual receivers of the array 201 are located atdifferent altitudes with respect to other receivers in the array (e.g.,one individual receiver of the array 201 may be located on a hillside ata higher elevation than another individual receiver located deep in avalley). However, no two individual receivers within array 201 occupythe same latitude and longitude. In this regard, if the positions of theindividual receivers of the array 201 were indicated on atwo-dimensional map of the surface 203, no two indications of thelocations of individual receivers would occupy the same space. Ininstances where a body of water covers the Earth's surface at thelocation where the receiver is to be placed, the receiver may be placedat the bottom of the body of water (e.g., on the sea floor). Further, itis possible for one or more of the receivers in array 201 to be buried.

The arrangement of the receivers in the array 201 may be configured toachieve particular characteristics and/or accommodate local terrain. Forexample, an array 301 in which the receivers are uniformly distributedthroughout an area encompassed by the array 301, such as thatillustrated in FIG. 3A, may be utilized. The overall size of the uniformarray 301 may be selected based on a surface wavelength corresponding tothe minimum frequency to be recorded. The spacing between the individualreceivers of the uniform array 301 may be selected based on a surfacewavelength corresponding to the maximum frequency to be recorded. Thenumber of receivers may be selected based on the bandwidth between thelowest and highest frequencies to be recorded.

The individual receivers may also be non-uniformly distributed asillustrated in the exemplary array 302 of FIG. 3B. In the non-uniformarray 302, the spacing between individual receivers of the array 302along the outer edges of the array 302 is greater than the spacingbetween the individual receivers of the array 302 toward the center ofthe array 302. In such an arrangement, the minimum and maximum distancesbetween individual receivers of the array 302 may be based on themaximum and minimum frequencies, respectively, of directionalitycomponents to be measured.

The individual receivers may also be randomly or partially randomlydistributed as illustrated in the exemplary array 303 of FIG. 3C. Suchan arrangement may be partially dictated by local topography, buildings,or other land and habitation features. For example, rough terrain maypreclude or make extremely difficult the formation of arrays such asthose illustrated in FIGS. 3A and 3B. Many other arrangements of theindividual receivers within the array are possible in addition to thearrangements illustrated in FIGS. 3A-3C.

Referring again to FIG. 2, the array 201 may be used to record data,determine directionality components, and compute multiplication factors.The array may also be used as a virtual source that applies themultiplication factors to modify the directionality components for aninterferometric seismic survey. An individual receiver located outsideof the array 201, such as receivers 205 and 206, may function as asecondary receiver for the seismic interferometric survey. Moreover, oneor more of the individual receivers of the array 201 may function asboth a member of the array 201 for purposes of directionality componentmodification and as a secondary receiver used for seismicinterferometry.

The data recorded by the array 201 may consist of a separate time seriesrecorded by each individual receiver of the array 201. This data may beused to determine the amplitude and directionality of seismicdirectionality components incident on the area of the array 201. Theamplitude and directionality determination may be accomplished using anyof a variety of spatial transform methods that transform the data overthe receiver locations into directionality components. This transformmay be accomplished by combining at least two of the time seriesrecorded by individual receivers of the array 201. For example, 1D or 2Dslant stacks, 1D or 2D beam forming, and/or 1D or 2D Fast FourierTransforms (FFTs) may be employed to determine the amplitude anddirectionality of seismic directionality components from the datarecorded by the array 201. Other methods, such as Radon, discreetcosine, Gabor and Wigner transforms may also be utilized. Variations ofthe above-mentioned methods may also be utilized. All these transforms,and others, share the property that they mathematically combine two ormore traces to produce the transformed data. Whatever process is used,uneven weighting and/or tapering may be employed during the process.Time shifts may be applied before the transform to correct for thedeviations of the receiver locations from a flat surface. The recordeddata may be converted from the time domain to another domain, such asthe frequency domain, prior to performing the spatial transform todetermine and modify directionality components. This process can beapplied for each ground motion component.

Once the array data is transformed into directionality components, thetotal energy for each directionality component may be measured. Othersignal strength measurement techniques may also be utilized. Themeasurement may be a single measurement for each directionalitycomponent direction or it can be multiple measurements for eachdirectionality component direction for the different data components ofeach trace domain, such as a time window or frequency.

An alternative way of measuring signal strengths of directionalitycomponents without performing a transformation is to apply a set ofmultiplication factors, time shifts, and phase rotations to theuntransformed data, sum the data, and measure signal strength from theresult. The set of multiplication factors, time shifts, and phaserotations are performed to emphasize and possibly isolate one or moredirectionality components. Then the process is repeated with a differentset of multiplication factors, time shifts, or phase rotations for adifferent directionality component or group of directionalitycomponents.

The measured directionality components may be used to compute themultiplication factors or to modify the directionality components of avirtual source at the location 202 of the array 201 for use in a seismicsurvey using seismic interferometry methods (a seismic interferometrysurvey). The directionality components (e.g., represented bydirectionality component vectors 103 a through 103 g in FIG. 1A) may bedetermined as described herein. To use this information to modify thedirectionality components of a virtual source in seismic interferometry,it may be assumed, as illustrated in FIG. 1B, that the Earth's surface102 is a perfect reflector of the directionality components. Forexample, directionality component vector 105 f represents adirectionality component vector that is a reflection of directionalitycomponent vector 103 f shown in FIG. 1A. Similarly, each directionalitycomponent vector 105 a through 105 g of FIG. 1B represents a reflectionof the directionality component vectors illustrated in FIG. 1A. Once thetime series data received at the virtual source array has beentransformed into separate directionality components, the amplitude ofthe directionality components can be modified with multiplicationfactors before further processing. The multiplication factors can beexplicitly applied to each directionality component or implicitly duringfurther manipulation of the data, such as active source seismicprocessing.

As shown in FIG. 2, one or more portions of one or more of the reflecteddirectionality components (e.g. represented by directionality componentvectors 105 a through 105 g in FIG. 1B) may be transmitted through theEarth from the first location 202 to the locations(s) of the additionalreceivers 205 and 206. Such reflected seismic waves are represented bydashed arrows 207 a through 207 c in FIG. 2, and as shown, some seismicwaves (e.g. 207 a) may remain in near surface waveguide structure 208.Other seismic waves (e.g. 207 b and 207 c) may penetrate deeperstructure 209 with some (e.g. 207 b) being refracted toward theadditional receivers 205 and 206 and some (e.g. 207 c) being reflectedat a boundary between deeper structure 209 and one or more still deeperstructures 210 a through 210 c.

The determined multiplication factors that are applied to thedirectionality components may be used to control a directionalityfunction of the virtual source used in seismic interferometry. Aspreviously noted, known methods of performing seismic interferometry donot take into account the non-uniform strengths of the seismic waveswith different directionality incident at the virtual source. As such,image distortion and noise may be at higher levels relative to an activesource seismic survey when using known seismic interferometry methods.This distortion and noise may be reduced or eliminated by modifying thedirectionality function of the virtual source. For example, thedirectionality of the virtual source may be controlled to produce auniform directionality similar to uniform seismic waves generated byactive sources. The resultant uniform directionality function may berepresented by uniform directionality component vectors such asdirectionality component vectors 401 a through 401 g of FIG. 4A. Thesedirectionality components are separate for each ground motion component.

Other desired directionalities of the virtual source may be utilized.For example, if it is desired to reduce noise in the collected data dueto seismic waves traveling near the surface (e.g., waves such as wave207 a of FIG. 2), the strength of waves reflected at the virtual sourceand traveling close to parallel with the Earth's surface (such as waves105 a and 105 g of FIG. 1B) may be deemphasized, while directionalitycomponents traveling at or near perpendicular to the Earth's surface(e.g., waves 105 c and 105 d of FIG. 1B) may be emphasized. Such anon-uniform directionality function may be represented by thedirectionality component vectors 402 a through 402 g of FIG. 4B. Sincenear surface seismic waves may introduce noise into data collectedduring a seismic survey, using a directionality function such as thatillustrated in FIG. 4B may serve to reduce the noise level andsubsequently improve image quality and reduce the amount of processingneeded in performing seismic interferometry with the collected data.Still other directionality functions may be created. For example, otherfunctions may be generated to emphasize particular ray paths, such asrefraction or reflection ray paths through a particular layer or sectionof the geologic structure being examined. Also, a directionalityfunction may be selected to compensate for certain geologic structure orto emphasize near surface seismic waves.

Creating a desired directionality function may include determiningmultiplication factors that may then be applied to modify the measureddirectionality function to the desired function. For example,multiplication factors may be determined by dividing the desiredstrength for a particular directionality component by the measuredstrength for that particular directionality component as describedherein in connection with FIGS. 4A & 4B. By way of further example,multiplication factors may be determined by dividing the desiredstrength for a particular directionality component by the square of themeasured strength for that particular directionality component. Moregenerally, multiplication factors (MF) may be determined by dividing thedesired strength (DS) for each individual transform component by themeasured signal strength (MS) for each individual transform componentraised to the power of N, wherein N is a real number (e.g. MF=DS/MS¹,MF=DS/MS^(1.5), MF=DS/MS², MF=DS/MS^(2.5), MF=DS/MS³, etc.). Squaringthe measured signal strength prior to dividing is particularly desirablein order to correct both source and receiver transform components.Expressed in another manner, determination of multiplication factorsmay, for example, be done once for correcting the source transformcomponent and a second time for correcting the receiver transformcomponent. In this regard, multiplication factors for correcting thesource transform component may be determined by dividing the desiredstrength for each individual source transform component by the measuredsignal strength for each individual source transform component, andmultiplication factors for correcting the receiver transform componentmay be determined by dividing the desired strength for each individualreceiver transform component by the measured signal strength for eachindividual receiver transform component. Regardless of how themultiplication factors are determined, in instances where the measuredstrength of a particular directionality component is below apredetermined threshold, the measured strength may be increased to avalue exceeding that threshold prior to the determination of themultiplication factor. In this manner, dividing the desired strength bya relatively small measured strength (and the corresponding largemultiplication factor) that may be unreliable can be avoided.

Where it is desired that the virtual source be a directionally uniformsource, the same desired strength may be used in determining eachmultiplication factor. Where it is desired that the virtual source be adirectionally non-uniform source, the desired strength used indetermining various multiplication factors may vary (e.g., to producethe non-uniform functions previously discussed).

Other methods may be used to measure the directionality components of avirtual source used to either compute the multiplication factors orapply the multiplication factors. In a first example, damping factorsmay be applied to certain measured directionality components (e.g.,directionality components traveling parallel to the Earth's surface). Ina second example, measurements made at a subset of receivers of thearray may be modified prior to determination of directionalitycomponents (e.g., the array readings may be tapered toward the edges ofthe array).

The processing described above in relation to data generated by thereceivers of the array may be performed on the entire recorded timeseries. Alternatively, one or more of the recorded time series may besubdivided into time window subsets and these subsets may be processedas described herein. This may include independently determiningmultiplication factors for each time window.

In instances where the data from the receivers of the array areconverted into a derivative domain of the time domain, multiplicationfactors may be separately determined and applied for each value in thederivative domain of the time domain. For example, where the derivativedomain of the time domain is the frequency domain, multiplicationfactors may be separately determined for each frequency value and eachdirectionality component.

Once determined, the multiplication factors may be utilized in a varietyof ways to enhance a seismic interferometry process. The multiplicationfactors may have a number of characteristics. For example, themultiplication factors may be non-unitary, and the multiplicationfactors may be complex numbers.

Moreover, the multiplication factors may be applicable over a widegeographic region, possibly hundreds of miles wide. The array used todetermine the multiplication factors can be different than the arrayused to apply the multiplication factors. In this regard, once aparticular set of multiplication factors are determined for a particularregion, that set of multiplication factors may be used to modify thedirectionality function of a plurality of virtual source arrays forseismic interferometry in that same region.

Multiplication factors may be applied in a variety of domains and duringdifferent steps or stages in the processing of the data in order tomodify the virtual source directionality function. The multiplicationfactors can be applied early in the interferometry processing, or laterin the active source seismic data processing/inversion step. Themultiplication factors can be applied in a spatial transform domain orthey can be applied in the untransformed domain when the multiplicationfactors may correspond to time shifts or phase rotations. A common traitof these methods is that they modify the directionality function of thevirtual source by combining two or more traces from the receivers in thearray.

One method for applying the multiplication factors to the virtual sourceis to transform the data recorded from the individual receivers of thearray into the same domain from which the multiplication factors arecomputed. Then the multiplication factors can be directly applied bymultiplying the appropriate components in the transform domain. Then thedata can be transformed back to its original spatial and time domain andthe data can be further processed with standard interferometrictechniques and active source seismic processing techniques. Or, insteadof transforming the data back to the original spatial and time domain,the data can be converted straight into a different domain used by thesubsequent interferometric techniques and seismic processing techniques.The data from the individual receivers of the array can be treated asseparate traces in the subsequent interferometric or seismic processing,or they can be reduced, combined, or summed into fewer traces. Thisprocess can be applied separately for each ground motion component wherethe traces from a single component are transformed or combined.

Another method for applying the multiplication factors is to transformthe data into a domain different than that used to compute themultiplication factors. In this case, the multiplication factors can betransformed from their original domain to the same domain as the seismicdata. The transform may involve interpolation from one function ofdirectionality representation to another. This transform of themultiplication factors can be done directly from one domain to another,or indirectly by inverse transforming the multiplication factors to aspatial domain, possibly resampling or interpolating them in the spatialdomain, and then transforming them to the new domain that is consistentwith that used for the data.

Alternately, the above methods of applying the multiplication factors inthe transform domain can be applied in later processing, either duringthe application of the interferometry processing, or during differentstages of seismic data processing. The interferometric processing or theseismic data processing may transform the array data into a differentdomain. The multiplication factors can then be applied in this domain,possibly transforming the multiplication factors as described above. Forexample, the data from the individual receivers or the array may gothrough standard interferometric processing to produce data similar tothat from conventional active sources. This data may then go throughactive source seismic data processing. Here, active source seismic dataprocessing is meant to imply any seismic processing techniques thatapply to conventional active source data. These techniques applied toconventional active source data may include standard known methods ornew inventive methods. As the data is processed by active source seismicdata processing, it may be transformed into a different domain, such asthe plane wave domain, or the Tau-P domain, where each componentcorresponds to some directionality. One such technique is plane wavemigration. When the data is in this domain, the multiplication factorscan be applied to modify the strength of the directionality components.This process can be applied separately for each ground motion componentwhere the traces from a single component are transformed or combinedtogether.

This application of multiplication factors during active sourceprocessing can be performed explicitly, as stated above, by transformingthe data into directionality components and modifying their strengths,or it can be performed implicitly. One approach of applying themultiplication factors implicitly is by performing a migration, animaging, or an inversion process, such as reverse time migration, thatsimulates a source. Normally this source simulation is done with a pointsource that has a uniform directionality function. By simulating asource with non-uniform directionality function, the multiplicationfactors can be applied implicitly. One can produce the non-uniformsimulated source directionality function that corresponds to themultiplication factors by taking the original uniform source, possiblyextending it over a larger region, transforming it into the same domainas the multiplication factors, apply the multiplication factors, andthen transforming back to the original domain. Conversely, one cantransform the multiplication factors to the same domain as the simulatedsource. The simulated source can use multiple ground motion components,each with a different directionality function.

A special case of applying the multiplication factors in a differentdomain from where they are computed is to apply the multiplicationfactors directly in the spatial domain. In this way, the multiplicationfactors can be applied to the data recorded at the individual receiversof the array without transforming the data. For example, themultiplication factors can be transformed into the spatial domain toproduce multiplication factors, time shifts, or phase rotations at thereceiver locations. This transformation may involve some interpolation.These new multiplication factors, time shifts, or phase rotations may beapplied early in the interferometric process or later during activesource processing. The data can be summed or partially combined as partof the application of the new multiplication factors, time shifts, orphase rotations. This process can be applied separately for each groundmotion component where the traces from a single component aretransformed, multiplied, or combined.

Furthermore, the directionality of a virtual source may be modified byinterconnecting the receivers of the array in such a manner that asingle aggregated time series recorded by the interconnected receiversmay be used as a modified virtual source. In this regard, the receiversmay be electronically interconnected. Electronic interconnections amongthe receivers may be accomplished, for example, by directly wiring themtogether, through wireless links or through a combination of wired andwireless connections in such a manner that the interconnection isfunctionally similar to applying multiplication factors, time shifts,phase rotations or a combination thereof to produce a virtual sourcewith a desired directionality function.

These and other techniques of modifying the directionality of a virtualsource used in seismic interferometry may be used in place of or inconjunction with the use of multiplication factors.

As discussed before, these approaches for applying the multiplicationfactors may performed on the whole data or on subsets from individualreceivers or from individual directionality components in the spatialtransform domain. The multiplication factors may be applied in the timedomain or a derivative of the time domain, such as the frequency domain.The multiplication factors may be different for each subset or they maybe identical. The subsets can be a time window, an individual frequencycomponent, or a group of frequencies.

The above examples of the application of multiplication factors atvarious stages of the process of determining underlying geologicstructure are exemplary. Other mathematically equivalent applications ofthe multiplication factors are also intended to be within the scope ofthe present invention. Additionally, various ones or all of theabove-described methods and/or their mathematical equivalents may becombined to modify and/or control the directionality of a virtualsource.

FIG. 5 is a flow chart of an embodiment of a method of performingseismic interferometry to obtain information related to subsurfacestructure. Although the flow chart illustrates the steps in a particularorder, this is for exemplary purposes only and the order of the stepsmay be rearranged from that depicted in FIG. 5. The first step 501illustrated in FIG. 5 may be to position a plurality of seismicreceivers in an array. The array may be within an area associated withthe location of a virtual source for seismic interferometry.

The next step 502 may be to use a seismic receiver as a secondarylocation receiver for seismic interferometry. This secondary locationreceiver may be one of the receivers of the array or it may be a seismicreceiver that is not part of the array. The secondary location receivermay be colocated within the area of the array or it may be locatedremote from the array (e.g., such as receiver 205 of FIG. 2).

The following step 503 may be to use the seismic receivers (e.g., thereceivers of the array and the secondary location receiver) to recordseismic waves incident on the seismic receivers. This recording may takethe form of a separate time series for every individual seismic receiverused. Alternatively, some or all of the outputs of the seismic receiversmay be combined prior to recording. For example, each of the seismicreceivers of the array may be electrically interconnected and a singletime series for the entire array may be recorded.

The next step 504 may be to modify a directionality function of thevirtual source for seismic interferometry. This may involve combining atleast two of the time series from the seismic receivers included in thearray. This combining may be performed after the time series have beenrecorded by, for example, a computer processor and computer programproduct. This combining may involve performing mathematical operationson the output signals of the seismic receivers of the array prior tocombining the outputs and recording a single time series for the array.

FIG. 6 is a flow chart of an embodiment of a method of modifying adirectionality function of a virtual source used in seismicinterferometry. Although the flow chart illustrates the steps in aparticular order, this is for exemplary purposes only and the order ofthe steps may be rearranged from that depicted in FIG. 6. The first step601 illustrated in FIG. 6 is to record seismic wave data incident oneach seismic receiver of an array of seismic receivers. The virtualsource may be associated with the area in which the array of seismicreceivers is located.

The following step 602 may be to perform a domain transform on therecorded seismic wave data of step 601. This domain transform may beperformed over the locations of the receivers of the array. The domaintransform may separate the recorded seismic wave data into differenttransform components (e.g., different directionality components). Thismay be followed by step 603 in which a signal strength for eachtransform component is measured.

The next step 604 may be to determine multiplication factors where themultiplication factors are operable to convert the measured signalstrength for each transform component into a desired signal strength foreach transform component. The multiplication factors may be determinedas described herein.

FIG. 7 is a block diagram of a system 700 operable to perform seismicinterferometry. The system 700 may include a plurality of seismicreceivers 701. The plurality of seismic receivers 701 may be arranged inan array or with a portion of the seismic receivers in an array and oneor more remotely located seismic receivers. The seismic receivers 701may be interconnected to a data recording device 703 via aninterconnection 702. The interconnection 702 may take several forms. Forexample, the interconnection 702 may be a hardwired link between theseismic receivers 701 and a data recording device 703. In anotherexample, the interconnection 702 may be a wireless link. In a furtherexample, the interconnection 702 may be a virtual link where individualseismic receivers are capable of storing data pertaining to seismicwaves incident on the individual seismic receiver on storage media(e.g., on a memory card or data storage disk). The data may then betransferred, via virtual interconnection 702, to the data recordingdevice 703 by transferring the recorded data from the storage media tothe data recording device 703. The interconnection 702 may comprise oneor more of the foregoing (hardwired, wireless, virtual).

The data recording device 703 may be operable to record data (e.g., timeseries of seismic waves incident on each seismic receiver) generated bythe seismic receivers 701 and store it on a data storage device 704. Thedata may be stored in the data storage device 704 in a variety ofmanners. For example, all of the data generated by the seismic receivers701 may be stored in a single data file such as data file 705. Inanother example, all of the data generated by the seismic receivers ofthe array may be stored in a single data file such as data file 705 andthe data generated by the seismic receiver or receivers used assecondary location receivers for seismic interferometry may be stored ina separate data file such as data file 706. Other data storageconfigurations, such as storing data generated by each individualseismic receiver of the seismic receivers 701 in its own data file, maybe used.

The data storage device 704 may be interconnected to a processor 707capable of executing a computer program product 708. The computerprogram product 708 may include computer program code stored, forexample, on a storage medium (e.g., memory, optical disk, hard drive,floppy disk). The computer program code may be operable to perform anyof the data processing (e.g., transforms, calculations, migrations)disclosed herein. In particular, the computer program code may enablethe processor 707 to read one or more of the data files 705, 706 and tocontrol a directionality function of a virtual source for seismicinterferometry. The modifying of the directionality function may involvecombining at least two time series from the seismic receivers includedin the array.

The computer program code may enable the processor to determine thedirectionality function incident on the array (e.g., the processor maybe operable to determine the directionality components). The computerprogram code may enable the processor to determine multiplicationfactors. The computer program code may enable the processor to apply themultiplication factors. The application of multiplication factors maytake place at various steps of the seismic surveying process aspreviously discussed.

Although the above detailed description generally describes embodimentsrelated to methods and apparatuses for modifying directionality ofseismic interferometry data with the use of an array, embodimentsdescribed herein may be utilized in other seismic interferometryapplications and in other configurations.

Additional modifications and extensions to the embodiments describedabove will be apparent to those skilled in the art. Such modificationsand extensions are intended to be within the scope of the presentinvention as defined by the claims that follow.

1. A method of modifying a directionality function of a virtual sourceused in seismic interferometry, said method comprising: recordingseismic wave data incident on each individual seismic receiver of anarray of seismic receivers, wherein each receiver of the array ofseismic receivers has an associated location within the array;performing a domain transform on the recorded seismic wave data over thearray locations of the receivers to separate the recorded seismic wavedata into different transform components, wherein each transformcomponent corresponds to a type of wave that has some directionality;measuring a signal strength measurement for each transform component;and determining multiplication factors to convert the measured signalstrength for each transform component into a desired strength for eachtransform component.
 2. The method of claim 1 wherein the multiplicationfactors are complex numbers.
 3. The method of claim 1 wherein the arrayof seismic receivers is used in performing seismic interferometry toobtain information related to subsurface structure.
 4. The method ofclaim 1 wherein the array of seismic receivers is co-located in a regionwith another array of seismic receivers used in performing seismicinterferometry to obtain information related to subsurface structure. 5.The method of claim 1 wherein said determining of multiplication factorscomprises: dividing the desired strength for each individual transformcomponent by the measured signal strength for each individual transformcomponent raised to the power of N, wherein N is a real number.
 6. Themethod of claim 5 wherein N=2, whereby the desired strength for eachindividual transform component is divided by the square of the measuredsignal strength for each individual transform component.
 7. The methodof claim 5 wherein N=1, whereby the desired strength for each individualtransform component is divided by the measured signal strength for eachindividual transform component.
 8. The method of claim 5 wherein saiddetermining of multiplication factors further comprises: increasing ameasured signal strength below a predetermined threshold to a valueexceeding the predetermined threshold prior to said dividing.
 9. Themethod of claim 1 wherein said determining of multiplication factors isdone once for correcting the source transform component and a secondtime for correcting the receiver transform component.
 10. The method ofclaim 9 wherein said determining of multiplication factors forcorrecting the source transform component comprises dividing the desiredstrength for each individual source transform component by the measuredsignal strength for each individual source transform component, andwherein said determining of multiplication factors for correcting thereceiver transform component comprises dividing the desired strength foreach individual receiver transform component by the measured signalstrength for each individual receiver transform component.
 11. A seismicinterferometric system operable to obtain information related tosubsurface structure, said system comprising: a plurality of seismicreceivers positionable to receive seismic waves, wherein at least aportion of the plurality of seismic receivers are arranged in an arraywithin an area associated with a location of a virtual source forseismic interferometry, and wherein at least one of the seismicreceivers is used as a secondary location receiver for seismicinterferometry; at least one recording device operable to record a timeseries of seismic waves incident on each seismic receiver of the arrayand on the secondary location receiver; and a processor operable tomodify a directionality function of the virtual source for seismicinterferometry, wherein said modifying involves combining at least twoof the time series from the seismic receivers included in the array, andwherein said processor is further operable to perform a domain transformon the recorded seismic wave data over the array locations of thereceivers to separate the recorded seismic wave data into differenttransform components, wherein each transform component corresponds to atype of wave that has some directionality, measure a signal strengthmeasurement for each transform component, and determine multiplicationfactors to convert the measured signal strength for each transformcomponent into a desired strength for each transform component bydividing the desired strength for each individual transform component bythe measured signal strength for each individual transform componentraised to the power of N, wherein N is a real number.
 12. The system ofclaim 11 wherein N=2, whereby the processor divides the desired strengthfor each individual transform component by the square of the measuredsignal strength for each individual transform component.
 13. The systemof claim 11 wherein N=1, whereby the processor divides the desiredstrength for each individual transform component by the measured signalstrength for each individual transform component.
 14. The system ofclaim 11 wherein said processor is further operable to increase ameasured signal strength below a predetermined threshold to a valueexceeding the predetermined threshold prior to said dividing.
 15. Thesystem of claim 11 wherein said processor is further operable to performa spatial domain transform over the array locations of the time seriesof seismic waves incident on each seismic receiver of the array, andwherein said processor is further operable to apply non-unitarymultiplication factors to the domain transformed time series of seismicwaves incident on each seismic receiver of the array.
 16. A computerprogram product comprising: a computer usable medium having computerprogram code embodied therein, the computer program code including:computer readable program code enabling a processor to read a data fileincluding a time series of seismic waves incident on each seismicreceiver of an array of seismic receivers, the array being associatedwith a location of a virtual source for seismic interferometry, the timeseries of seismic waves incident on each seismic receiver of the arraycomprising seismic wave data; computer readable program code enabling aprocessor to read a data file including a time series of seismic wavesincident on a secondary location receiver for seismic interferometry;computer readable program code enabling a processor to modify adirectionality function of the virtual source for seismicinterferometry, wherein said modify involves combining at least two ofthe time series from the seismic receivers included in the array;computer readable program code enabling the processor to perform adomain transform on the recorded seismic wave data over the arraylocations of the receivers to separate the recorded seismic wave datainto different transform components, wherein each transform componentcorresponds to a type of wave that has some directionality; computerreadable program code enabling the processor to measure a signalstrength measurement for each transform component; and computer readableprogram code enabling the processor to determine multiplication factorsto convert the measured signal strength for each transform componentinto a desired strength for each transform component by dividing thedesired strength for each individual transform component by the measuredsignal strength for each individual transform component raised to thepower of N, wherein N is a real number.
 17. The computer program productof claim 16 wherein N=2, whereby the computer readable program codeenables the processor to divide the desired strength for each individualtransform component by the square of the measured signal strength foreach individual transform component.
 18. The computer program product ofclaim 16 wherein N=1, whereby the computer readable program code enablesthe processor to divide the desired strength for each individualtransform component by the measured signal strength for each individualtransform component.
 19. The computer program product of claim 16further comprising computer readable program code enabling the processorto increase a measured signal strength below a predetermined thresholdto a value exceeding the predetermined threshold prior to said dividing.20. The computer program product of claim 16 further comprising:computer readable program code enabling the processor to perform aspatial domain transform over the array locations of the time series ofseismic waves incident on each seismic receiver of the array thatseparates the time series of seismic waves incident on each seismicreceiver of the array into different directionality components, whereineach directionality component corresponds to a value of thedirectionality function; and computer readable program code enabling theprocessor to apply non-unitary multiplication factors to the domaintransformed time series of seismic waves incident on each seismicreceiver of the array.